1. Field of the Invention
The present invention relates generally to drill bits and more generally to a bit designed to shift orientation in a predetermined direction as it drills. Even more particularly, the preferred embodiment relates to a drill bit having inclination reducing or dropping tendencies.
2. Background Art
Drill bits, in general, are well known in the art. The bit is attached to the lower end of the drill string and is typically rotated by rotating the drill string at the surface or by a downhole motor, or by both methods. The bit is typically cleaned and cooled during drilling by the flow of drilling fluid out of one or more nozzles on the bit face. The fluid is pumped down the drill string, flows across the bit face, removing cuttings and cooling the bit, and then flows back to the surface through the annulus between the drill string and the borehole wall.
The cost of drilling a borehole is proportional to the length of time it takes to drill the borehole to the desired depth and location. The drilling time, in turn, is greatly affected by the number of times the drill bit must be changed in order to reach the targeted depth or formation. This is the case because each time the bit is changed the entire drill string, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the new bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. This process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is always desirable to minimize the number of trips that must be made in a given well.
In recent years a majority of bits have been designed using hard polycrystalline diamond compacts (PDC) as cutting or shearing elements. The cutting elements or cutters are mounted on a rotary bit and oriented so that each PDC engages the rock face at a desired angle. The PDC bit has become an industry standard for cutting formations of grossly varying hardnesses. The cutting elements used in such bits are formed of extremely hard materials and include a layer of polycrystalline diamond material. In the typical PDC bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of the bit body. A cutter element typically has a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. The cutting layer is exposed on one end of its support member, which is typically formed of tungsten carbide. As used herein, reference to a “PDC” bit or “PDC” cutting element includes superabrasive materials such as polycrystalline diamond, cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide.
The configuration or layout of the PDC cutters on a bit face varies widely, depending on a number of factors. One of these is the formation itself, as different cutting element layouts cut the various strata differently. In running a bit, the driller may also consider weight on bit, the weight and type of drilling fluid, and the available or achievable operating regime. Additionally, a desirable characteristic of the bit is that it be “stable” and resist vibration, the most severe type or mode of which is “whirl,” which is a term used to describe the phenomenon wherein a drill bit rotates about an axis that is offset from the geometric center of the drill bit. Whirling subjects the cutting elements on the bit to increased loading, which may cause the premature wearing or destruction of the cutting elements and a loss of penetration rate. Alternatively, U.S. Pat. Nos. 5,109,935 and 5,010,789 disclose techniques for reducing whirl by compensating for imbalance in a controlled manner, the contents of which are hereby incorporated by reference. In general, optimization of cutter placement and orientation and overall design of the bit have been the objectives of extensive research efforts.
Directional and horizontal drilling have also been the subject of much research. Directional and horizontal drilling involves deviation of the borehole from vertical. Frequently, this drilling program results in boreholes whose remote ends are approximately horizontal. Advancements in measurement while drilling (MWD) technology have made it possible to track the position and orientation of the wellbore very closely. At the same time, more extensive and more accurate information about the location of the target formation is now available to drillers as a result of improved logging techniques and methods, such as geosteering. These increases in available information have raised the expectations for drilling performance. For example, a driller today may target a relatively narrow, horizontal oil-bearing stratum, and may wish to maintain the borehole within the stratum once the borehole has entered the stratum. In more complex scenarios, highly specialized “design drilling” techniques are preferred, with highly tortuous well paths having multiple directional changes of two or more bends lying in different planes.
A common way to control the direction in which the bit is drilling is to steer using a turbine, downhole motor with a bent sub and/or housing. As shown in FIG. 1, a simplified version of a downhole steering system according to the prior art comprises a rig 1, drill string 2 having a motor 6 with or without a bent sub 4, and drill bit 8. The motor 6, with or without a bent sub 4, forms part of the bottom hole assembly (BHA). These BHA components are attached to the lower end of the drill string 2 adjacent the bit 8. When not rotating, the bent sub 4 causes the bit face to be canted with respect to the tool axis. The motor is capable of converting fluid pressure from drilling fluid pumped down the drill string into rotational energy at the bit. This presents the option of rotating the bit without rotating the drill string. When a downhole motor is used with a bent housing and the drill string is not rotated, the rotating action of the motor normally causes the bit to drill a hole that is deviated in the direction of the bend in the housing. When the drill string is rotated, the borehole normally maintains direction, regardless of whether a downhole motor is used, as the bent housing rotates along with the drill string and thus no longer orients the bit in a particular direction. Hence, a bent housing and downhole motor are effective for deviating a borehole.
When a well is substantially deviated by several degrees from vertical and has a substantial inclination, such as by more than 30 degrees, the factors influencing drilling and steering change as compared to those of a vertical well. This change in factors reduces operational efficiency for a number of reasons.
First, operational parameters such as weight on bit (WOB) and RPM have a large influence on the bit's rate of penetration, as well as its ability to achieve and maintain the required well bore trajectory. As the well's inclination increases and approaches horizontal, it becomes much more difficult to apply weight on bit effectively, as the well bottom is no longer aligned with the force of gravity. Furthermore, the increasing bend in the drill string means that downward force applied to the string at the surface is less likely to be translated into WOB, and is more likely to increase loading that can cause the buckling or deforming of the drill string. Thus, attempting to steer with a downhole motor and a bent sub normally reduces the achievable rate of penetration (ROP) of the operation, and makes tool phase control very difficult.
Second, using the motor to change the azimuth or inclination of the well bore without rotating the drill string, a process commonly referred to as “sliding,” means that the drilling fluid in most of the length of the annulus is not subject to the rotational shear that it would experience if the drill string were rotating. Drilling fluids tend to be thixotropic, so the loss of this shear adversely affects the ability of the fluid to carry cuttings out of the hole. Thus, in deviated holes that are being drilled with the downhole motor alone, cuttings tend to settle on the bottom or low side of the hole. This increases borehole drag, making weight-on-bit transmission to the bit very difficult and causing problems with tool phase control and prediction. This difficulty makes the sliding operation very inefficient and time consuming
Third, drilling with the downhole motor alone during sliding deprives the driller of the advantage of a significant source of rotational energy, namely the surface equipment that would otherwise rotate the drill string and reduce borehole drag and torque. The drill string, which is connected to the surface rotation equipment, is not rotated during drilling with a downhole motor during sliding. Additionally, drilling with the motor alone means that a large fraction of the fluid energy is consumed in the form of a pressure drop across the motor in order to provide the rotational energy that would otherwise be provided by equipment at the surface. Thus, when surface equipment is used to rotate the drill string and the bit, significantly more power is available downhole and drilling is faster. This power can be used to rotate the bit or to provide more hydraulic energy at the bit face, for better cleaning and faster drilling.
In addition to the directional drilling described in the discussion of FIG. 1, it is also desirable to have a drill bit that is capable of returning to a vertical drilling orientation (without the aid of an external steering mechanism such as turbine or bent sub) should the bit inadvertently deviate from vertical. The ability of a bit to return to a vertical path after deviating from such a path is known in the art as “dropping”. In order to effect dropping, such a drill bit must also have the capability of drilling or penetrating the earth in a direction that is not parallel with the longitudinal axis of the bit. It is therefore desirable to have cutting elements on the side of the bit to allow for such cutting action.
As shown in the schematic view of FIG. 2, a drill string assembly 50 consisting of a drill string 53 and a bit 51, is shown drilling a borehole 55 that has deviated from vertical. Drill string assembly 50 has a weight vector 52 that consists of an axial component 54 and a normal component 56. Unlike the directional drilling operations described above, such deviations from vertical are sometimes unintentional, and it is desirable in many instances to return drilling assembly 50 to a vertical orientation while drilling. In such a case, it is necessary for drill bit 51 to drill in a direction that is not parallel to axial vector 54 when the borehole has deviated from a desired vertical position. This can be accomplished by removing material from a side wall 57, rather than just a bottom portion 58, of borehole 55. As explained in more detail below, the ability to remove material from side wall 57 in a deviated borehole is enhanced when a bit 51 generates increased forces parallel to normal component 56 during operation.
In recent years, drill bits with asymmetric blade designs have been proposed and used in directional applications to generate forces during drilling that are not parallel to the axial vector 54 in a deviated well. Conventionally, these designs include “active” regions wherein cutters are positioned on blades of a bit to extend and form a primary cutting profile of the bit, and “passive” regions wherein cutters on selected blades of the bit are positioned to be recessed from the primary cutting profile formed by the active cutters. This arrangement leads to increased loading on the “active” side of the bit which results in off-axis forces that enhance the dropping tendencies of the bit. This also reduces the tendencies of the bit to whirl. However, as these bits are being pushed to drill longer segments through earth formation, it has been found that recessing the cutters on a passive side of a bit design may also lead to reduced durability and limited bit life. This is due to a reduction of the number of active cutters on the bit which result in increased loading on the remaining active cutters. The passive cutters pulled off profile generally do not actively drill the formation until the active cutters have undergone significant wear. As a result, excessive cutter wear may be seen on cutters and blades in the active regions of the bit. Cutter breakage and/or premature cutter loss may also occur in the cone and nose region before a desired drilling depth is reached.
Accordingly, an improved directional drilling bit is desired that allows for off-axis drilling in a deviated well by exerting a force against the side of the borehole and increased durability and bit life.